Hydraulic fracturing is a common stimulation technique used to enhance production of fluids from subterranean formations in, for example, oil, gas, coal bed methane and geothermal wells. In a typical hydraulic fracturing treatment operation, a viscosified fracturing fluid is pumped at high pressures and high rates into a wellbore penetrating a subterranean formation to initiate and propagate a hydraulic fracture in the formation. Subsequent stages of viscosified fracturing fluid containing particulate matter known as proppant, e.g., graded sand, ceramic particles, bauxite, or resin coated sand, are then typically pumped into the created fracture. The proppant becomes deposited into the fractures, forming a permeable proppant pack. Once the treatment is completed, the fracture closes onto the proppant pack, which maintains the fracture and provides a fluid pathway for hydrocarbons and/or other formation fluids to flow into the wellbore.
The fracturing fluid is usually a water-based fluid containing a gelling agent, e.g., a polymeric material that absorbs water and forms a gel as it undergoes hydration. The gelling agent serves to increase the viscosity of the fracturing fluid. The increased viscosity provides a number of advantages, including, among other things, improving the fracture propagating ability of the fluid and enabling the fracturing fluid to suspend and carry effective amounts of proppant.
The use of slick water fracturing fluids, which employ a friction reducer, but which generally do not employ a viscosifying agent, is well known in the industry. Most friction reducers used in slickwater fracture stimulation are high molecular weight polyacrylamides in mineral oil emulsions. However, at the concentrations of friction reducer typically employed in slickwater fracturing fluids, which concentrations typically range from about 0.5 gpt to 2 gpt, it is believed that the mineral oil and polyacrylamide in the emulsions can cause a buildup of polymer cake residue that can damage the well formations. For this reason, breakers are sometimes introduced into the slick water fracturing fluids to reduce the size of the polymer chains, and thereby potentially reduce fracture and formation damage.
Aqueous fracturing fluids gelled with viscoelastic surfactants (VESs) are also known in the art. VES-gelled fluids have been widely used as fracturing fluids because they exhibit excellent rheological properties and are less damaging to producing formations than crosslinked polymer fluids. VES fluids are non-cake-building fluids, and thus leave little or no potentially damaging polymer cake residue. However, viscoelastic surfactant gels do not reduce friction at high pump rates, because the micellar structure of the gels is disrupted at high shear rates.
Maintaining a desired viscosity of the gels can have benefits, such as effectively minimizing erosion due to abrasion between the well equipment and the proppant. The erosion or abrasion can result in damage to the pumping equipment and/or well tubulars that are bombarded by the proppant at high flow rates. Further, the ceramic proppant often used in high temperature, high closure wells can be of high density and abrasive, which can exacerbate this problem.
Conventional polyacrylamide emulsion friction reducers can also be difficult to add to cold water fracturing fluids, requiring extended time periods to hydrate in cold water, or the use of additional surfactants and/or heat to hydrate within a desired time frame. Further, conventional polyacrylamide friction reducers often are not generally compatible for use with salt, and therefore may not be suitable for use with hard water, brines or produced water (water that is produced by the well and that generally has high concentrations of total dissolved solids or salts).
Thus, there exists a need for improved well servicing fluids that can reduce or eliminate one or more of the problems discussed above.